1. Field
The invention relates generally to fluid characterization using nuclear magnetic resonance (NMR) instruments.
2. Background Art
The oil and gas industry has developed various tools capable of determining and predicting earth formation properties. Among different types of tools, nuclear magnetic resonance (NMR) instruments have proven to be invaluable. NMR instruments can be used to determine formation properties, such as the fractional volume of pore space and the fractional volume of mobile fluid filling the pore space. A general background of NMR well logging is described in U.S. Pat. No. 6,140,817.
NMR is a phenomenon resulting from interactions between nuclei and magnetic fields. When nuclei, which may have magnetic nuclear moments, i.e., non-zero spin angular momentum, are placed in a magnetic field B0, assumed in the z-direction, two energy levels are formed corresponding to the nuclear magnetic moment oriented along and against B0, respectively. Transitions between the two energy levels result in an electromagnetic signal characterized by the Larmor frequency, ω0=γB0, where γ is the gyromagnetic ratio of the nucleus and is a characteristic property of a nuclear species. The Larmor frequency is also the precession frequency of the nucleus in the magnetic field.
For a group of nuclei at equilibrium in a static magnetic field B0, the net magnetization vector (due to nuclear spin) is along the direction of B0. The nuclei can be excited to a higher energy level, e.g., by an RF pulse. The excited nuclei tend to relax to their equilibrium state in the direction of B0. The time constant associated with this relaxation process is referred to as the spin-lattice relaxation time, or longitudinal relaxation time (T1), which is a characteristic time for the longitudinal magnetization Mz.
For nuclei having a magnetization component in the x-y plane, the nuclei will have a precession motion in the x-y plane. The net magnetization in the x-y plane de-phases on a time scale T2, called the spin-spin relaxation time, or transverse relaxation time.
Borehole fluid sampling and testing tools such as Schlumberger's Modular Dynamics Testing (MDT) Tool can provide important information on the type and properties of reservoir fluids in addition to providing measurements of reservoir pressure. These tools may perform measurements of the fluid properties downhole, using sensor modules on board the tools. Alternatively, these tools can withdraw fluid samples from the reservoir that can be collected in vessels and brought to the surface for analysis. The collected samples are routinely sent to fluid properties laboratories for analysis of physical properties that include, among other things, oil viscosity, gas-oil ratio, mass density or API gravity, molecular composition, H2S, asphaltenes; resins, and various other impurity concentrations. However, if the samples are contaminated by mud filtrate, the laboratory data may not be useful or relevant to the reservoir fluid properties.
For example, the collected fluid samples could be emulsions of filtrate water and crude oil or, in wells drilled with oil-base muds, mixtures of reservoir crude oil and oil-base mud filtrate (OBMF). In either case the contamination may render the measured laboratory data irrelevant to the actual properties of the in situ reservoir fluids. In order for fluid sampling tool or laboratory measurements of reservoir fluid samples to be relevant, the samples must have low levels of contamination. In those cases where the samples brought to the surface have low or negligible contamination, laboratory results can still be tainted (e.g., by precipitation of solids caused by temperature changes).
It is well known that the reservoir fluid samples taken should avoid contamination from drilling mud filtrate in order to yield pressure-volume-temperature (PVT) properties that are truly representative of the native fluids. Furthermore, knowledge of accurate contamination levels is critical because too much contamination can lessen or negate the value of PVT laboratory measurements made on fluid samples, as well as downhole measurements made on such samples. Prior art methods disclose various methods for determining contamination levels, including measuring various physical properties of the fluid mixture. For example, U.S. Patent Application Publication US 2004/0254732 A1 by Storm et al. and U.S. Patent Application Publication US 2005/0182566 A1 by DiFoggio disclose methods and apparatus for determining the extent of contamination by measuring density. U.S. Pat. No. 6,274,865 B1 issued to Schroer et al. discloses methods and apparatus for determining the extent of contamination by measuring optical density.
Prior art methods use either mixing law equations or other empirical equations, which require knowledge of endpoint fluid properties (e.g., densities of the oil-base mud filtrate and the native oil) for quantitative estimation of contamination. However, in practice, there is usually at most one reliably known endpoint, i.e., that corresponding to 100% contamination. The endpoint corresponding to the native hydrocarbon (0% contamination) is generally not known. Without both endpoints, the estimation of contamination using prior art methods may only be qualitatively accurate.
There are other prior art methods that attempt to predict contamination from NMR measurements. The “sharpness” of an NMR relaxation time distribution was introduced as an indicator of OBMF contamination by Bouton, J. et al. (SPE Paper 71714 presented at the ATCE in New Orleans, La., 2001). This method is not reliable because it assumes that only OBMFs have a narrow relaxation time distribution. On the contrary, it is well known that low-viscosity crude oils, water, and gas also have narrow relaxation time distributions. U.S. Patent Application Publication 2005/0216196 A1 by Akkurt et al. discloses a method based on a family of different viscosity mixing laws and temporal contamination models. However, there are at least two drawbacks to the Akkurt et al. teachings: (1) the viscosity mixing laws disclosed by Akkurt et al. have not been shown to be valid for crude oils mixed with OBMF and, moreover, the different mixing laws predict different contaminations for the same mixture; (2) mixing laws require knowledge of the native oil properties (i.e., 0% contamination), which are generally not available in practical applications.
As described above, there is a need for a more direct and robust method for determining the level of OBMF contamination while the fluid is still within reservoirs and under the reservoir conditions, as well as in a laboratory.